Hazard Avoidance During Well Re-Entry

ABSTRACT

A system may include a downhole tool conveyable into a wellbore on a conveyance, and a plurality of sensing devices positioned at a distal end of the downhole tool to emit wave energy in an axial direction within the wellbore. At least a portion of the wave energy are reflected by one or more wellbore hazards and received by the plurality of sensing devices. The system further includes a data acquisition system communicatively coupled to the downhole tool to receive and process reflected wave energy and thereby identify the one or more wellbore hazards.

BACKGROUND

Once a wellbore has been drilled, it may be required to re-enter the wellbore to conduct various operations, such as logging, completing, intervention, etc. In many cases, this re-entry occurs long after the wellbore has been drilled and completed. During that time, wellbore conditions may have changed. For instance, the inner diameter of the wellbore may no longer be the same as it was when it was originally drilled and/or completed. In other cases, there may be a buildup of material deposits (paraffin, scales, etc.) on the walls of the wellbore or casing that lines the wellbore. In yet other cases, the casing may have been damaged, or the wellbore may contain various trapped objects (tools) that have inadvertently fallen into the well.

Due to these various obstructions in the wellbore, downhole conveyances, such as a string of jointed pipe or coiled tubing, may become stuck or damaged when re-entering and traversing the wellbore. This often creates a large amount of non-productive time trying to get the conveyance unstuck, and can cause damage to the conveyances and to any tools attached to the conveyances, loss of the tools, or even loss of use of the well. Even when the conveyances are not stuck, the speed at which the conveyance is lowered into or pulled out of the well is often slow due to being cautious of unknown hazards or obstacles. Being able to run in and out of a well at optimal speed would greatly decrease well operation costs.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, without departing from the scope of this disclosure.

FIG. 1 illustrates a well system that may embody or otherwise employ one or more principles of the present disclosure.

FIG. 2A illustrates an enlarged perspective view of a distal end of the downhole tool in FIG. 1 depicting a configuration of the plurality of sensing devices.

FIG. 2B illustrates another enlarged perspective view of the distal end of the downhole tool in FIG. 1 depicting another configuration of the plurality of sensing devices.

DETAILED DESCRIPTION

The present disclosure is related to a system that detects obstacles and hazards in the wellbore ahead of the string and communicates that information in real time so that the speed/force with which the string is forced into the well can be controlled to mitigate this problem.

Presently, downhole tools having video cameras are lowered into wellbores on a conveyance and used to detect any hazards (or obstructions) that may be present in the wellbore. However, in order for the video cameras of the downhole tool to image the wellbore hazards that may be present ahead of the downhole tool, it is required that clear fluids be present in the wellbore. Acoustic tools are sometimes used instead to detect potential hazards present in the wellbore. However, existing acoustic tools only image the wellbore in the radial direction and, therefore, have to be moved past a point in the wellbore in order to detect any hazard present at that point. Accordingly, existing acoustic tools are not configured to “look” ahead of the downhole tool in the wellbore.

Embodiments disclosed herein help to better identify wellbore hazards present in the wellbore and make better decisions about how to remove or clean out the wellbore hazards. This reduces non-productive time during wellbore operations due to downhole tools or conveyances being stuck in the wellbore due to unknown hazards or obstacles, reduces the cost of poor quality, and the costs incurred due to lost tools. Embodiments disclosed herein also allow for optimal speed of travel into and out of the wellbore without the fear of hitting the wellbore hazards present in the wellbore.

Referring to FIG. 1, illustrated is a well system 100 that may embody or otherwise employ one or more principles of the present disclosure, according to one or more embodiments. As illustrated, the well system 100 may include a service rig 102 that is positioned on the earth's surface 104 and extends over and around a wellbore 106 that penetrates a subterranean formation 108. The service rig 102 may be a drilling rig, a completion rig, a workover rig, or the like. In some embodiments, the service rig 102 may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure. Moreover, while the well system 100 is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure could equally be applied in any sea-based or sub-sea application where the service rig 102 may be a floating platform, a semi-submersible platform, or a sub-surface wellhead installation as generally known in the art.

The wellbore 106 may be drilled into the subterranean formation 108 using any suitable drilling technique and may extend in a substantially vertical direction away from the earth's surface 104 over a vertical wellbore portion 110. At some point in the wellbore 106, the vertical wellbore portion 110 may deviate from vertical relative to the earth's surface 104 and transition into a substantially horizontal wellbore portion 112. In some embodiments, the wellbore 106 may be completed by cementing a casing string 114 within the wellbore 106 along all or a portion thereof. In other embodiments, however, the casing string 114 may be omitted from all or a portion of the wellbore 106 and the principles of the present disclosure may equally apply to an “open-hole” environment.

The system 100 may further include a downhole tool 116 that may be conveyed into the wellbore 106 on a conveyance 118 that extends from the service rig 102. In some embodiments, the conveyance 118 may comprise a cable having one or more electric lines and/or fiber optic waveguides. In at least one embodiment, the cable and the conveyance 118 may comprise the same structure. In other embodiments, however, the conveyance 118 and the cable may not be the same and the cable may instead be coupled to the conveyance 118 and otherwise strung along therewith, but not used to lower the downhole tool 116 into the wellbore 106. Suitable conveyances 118 in this case can include drill pipe, coiled tubing, production tubing, a downhole tractor, and the like.

In some embodiments, the conveyance 118 (and/or the cable) may be in communication at the surface with a data processing unit 124 and may provide real time bidirectional communication between the downhole tool 116 and the data processing unit 124. The data processing unit 124 may include a signal processor 126 communicably coupled to a computer-readable storage medium 128 storing a program code executed by the processor 126. The results of the processing may be displayed on a display 130. Examples of a computer-readable storage medium include non-transitory medium such as random access memory (RAM) devices, read only memory (ROM) devices, optical devices (e.g., CDs or DVDs), and disk drives.

According to the present disclosure, the downhole tool 116 may comprise an array of sensing devices 117 located at a distal end thereof. As used herein, the term “distal” refers to the portion of the component that is furthest from the wellhead. Each sensing device 117 may emit a wave energy 121 into the wellbore 106 to detect one or more wellbore hazards 122 present in the wellbore 106. For the purpose of discussion herein, the wellbore hazards 122 may include any obstacle that may impede advancement of the downhole tool 117 or the conveyance 118 within the wellbore 106. Example wellbore hazards 122 include, but are not limited to, a tool lost in the wellbore 106, damaged casing 114, buildup of a substance (e.g., paraffin, scale, etc.) in the wellbore 106, or any combination thereof.

It will be appreciated by those skilled in the art that even though FIG. 1 depicts the downhole tool 116 as being arranged and operating in the horizontal portion 112 of the wellbore 106, the embodiments described herein are equally applicable for use in portions of the wellbore 106 that are vertical, deviated, or otherwise slanted.

FIG. 2A illustrates an enlarged perspective view of a distal end 119 of the downhole tool 116 of FIG. 1. As illustrated, the sensing devices 117 may be arranged in a desired configuration on a leading face 115 of the downhole tool 116 at the distal end 119. In at least one embodiment, as illustrated, the sensing devices 117 may be angularly offset from each other on the leading face 115 by equidistant spacing. In other embodiments, however, the sensing devices 117 may be angularly offset from each other on the leading face 115 by random spacing, without departing from the scope of the disclosure.

The sensing devices 117 may be arranged such that the wave energy 121 from each of the sensing devices 117 is emitted in a generally axial direction within the wellbore 106 (or the casing 114, FIG. 1). As used herein, axial direction refers to the direction that is substantially parallel to the longitudinal axis A of the wellbore 106 and/or the downhole tool 116. However, the wave energy 121 emitted can have a range of axial angles φ, such as anything less than 90° with respect to the longitudinal axis A. As illustrated in

FIG. 2A, the axial angle φ is defined between the direction of travel of the wave energy 121 and the longitudinal axis of the wellbore 106 and/or the casing 114.

In one example, the wave energy 121 emitted by the sensing devices 117 may include acoustic wave energy and the sensing devices 117 may comprise acoustic sensing devices, each of which may include an acoustic wave generator and an acoustic sensor. The acoustic wave generator emits acoustic waves through fluid present in the wellbore 106. The acoustic waves may be reflected back to the sensing devices 117 by the wellbore hazards 122.

In another example, the wave energy 121 may comprise pressure pulses and the sensing devices 117 may alternatively comprise pressure sensing devices, each of which includes a pressure pulse generator and a pressure sensor. The pressure pulse generator transmits a pressure pulse through the fluid in the wellbore 106, at least a portion of which may be reflected by the wellbore hazards 122. The reflected pressure pulse may then be received by the pressure sensing devices.

In yet another example, the wave energy 121 may include radiant energy, such as visible light, gamma rays, radio waves, ultraviolet light, infrared radiation, and the sensing devices 117 may include suitable devices for sensing the radiant energy. For instance, if the wave energy 121 includes visible light, then the sensing devices 117 may include optical sensing devices, each of which may include a light pulse generator and an optical sensor. The light pulse generator emits light pulses through the fluid and any light pulse reflected by one or more wellbore hazards 122 in the wellbore 106 is received by the optical sensor.

In still other examples, the wave energy 121 may include electromagnetic (EM) waves and the sensing devices may include EM transceivers, each including an EM source that emits EM waves and an EM receiver that receives EM waves reflected from the wellbore hazards 122.

It should be noted that wave energy 121 are not limited to the examples noted herein, and may include other kinds of wave energy, without departing from the scope of the disclosure. It should also be noted that it is not necessary for all of the sensing devices 117 to sense the same parameter. For example, one sensing device 117 could sense pressure waves, while another sensing device 117 on the same downhole tool 116 could sense radiant energy waves.

The distance that the wave energy 121 propagates into the wellbore 106 may define a field of view 120 of the downhole tool 116. As the downhole tool 116 is conveyed downhole, the wellbore hazards 122 that lie within the field of view 120 may be detected. The sensing devices 117 may be arranged such that the wave energy exhibits the field of view 120 having a pre-determined shape and extending a pre-determined axial distance L (e.g., about 5-10 feet) from the distal end 119 of the downhole tool 116. For instance, as illustrated in FIG. 2A, the field of view 120 is generally conical or frustoconical in shape.

In an embodiment, the sensing devices 117 may transmit wave energies 121 having different frequencies. Since different frequencies are absorbed or reflected differently by different materials, by choosing frequencies with different absorption/reflection rates, the size, shape and the material of the wellbore hazards 122 can be determined. For instance, a relatively harder material may reflect a relatively larger amount of frequencies as compared to a relatively softer material. As a result, the hardness of the material of the wellbore hazards 122 can be determined and would permit distinguishing between “hard” and “soft” wellbore hazards 122 (like steels and paraffins). The frequencies that are received by the sensing devices 117 are communicated to the data processing unit 124 that may process the received frequencies to produce an image of the wellbore hazards 122 that is displayed on the display 130.

In another embodiment, based on the time difference between the time the wave energy 121 was transmitted by the sensing device 117 and the time the reflected wave energy 121 was received by the sensing device 117, the data processing unit 124 (FIG. 1) may determine a distance to the one or more wellbore hazards 122. Once the size, shape, and/or material of the wellbore hazards 122, and a distance to the wellbore hazards 122 are determined, an operator may undertake appropriate remedial actions to remove or repair the hazard 122. The operator can control the sensing devices 117 via the data processing unit 124 to vary the emitted frequencies to obtain a better image of the wellbore hazards 122. This may provide a better understanding of the size and shape of the wellbore hazards 122, and/or better identify the material of the wellbore hazards 122. The remedial actions can then be modified to more efficiently remove the hazard 122 or aim a cleanout tool (or verify the quality of the clean out).

FIG. 2B illustrates another enlarged perspective view of the distal end 119 of the downhole tool 116 of FIG. 1. FIG. 2B may be similar in some respects to FIG. 2A, and therefore may be best understood with reference thereto where like numerals designate like components not described again in detail. In the illustrated embodiment in FIG. 2B, the sensing devices 117 may be arranged about the outer periphery of the downhole tool 106 at the distal end 119 thereof. Again, the sensing devices 117 may be arranged such that the wave energy 121 from each of the sensing devices 117 is emitted in a generally axial direction. It should be noted that the configuration (or the placement) of the sensing devices 117 on the downhole tool 116 in FIGS. 2A and 2B is merely an example and that any configuration of the sensing devices 117 that results in the wave energy 121 being emitted in the axial direction is within the scope of this disclosure.

Embodiments Disclosed Herein Include:

A. A system that includes a downhole tool conveyable into a wellbore on a conveyance, a plurality of sensing devices positioned at a distal end of the downhole tool to emit wave energy in an axial direction within the wellbore, at least a portion of the wave energy being reflected by one or more wellbore hazards and received by the plurality of sensing devices, and a data acquisition system communicatively coupled to the downhole tool to receive and process reflected wave energy and thereby identify the one or more wellbore hazards.

B. A method that includes conveying a downhole tool into a wellbore on a conveyance, emitting wave energy in an axial direction within the wellbore using a plurality of sensing devices positioned at a distal end of the downhole tool, at least a portion of the wave energy being reflected by one or more wellbore hazards, receiving reflected wave energy using the plurality of sensing devices, receiving and processing the reflected wave energy with a data acquisition system communicatively coupled to the downhole tool, and identifying the one or more wellbore hazards with the data acquisition system based on the reflected wave energy.

Each of embodiments A and B may have one or more of the following additional elements in any combination: Element 1: wherein the plurality of sensing devices are located on a leading face of the downhole tool.

Element 2: wherein the plurality of sensing devices are located about an outer periphery of the downhole tool at the distal end. Element 3: wherein the wave energy emitted by the plurality of sensing devices exhibits a field of view having a pre-determined shape and extends a pre-determined distance from the distal end of the downhole tool. Element 4: wherein the data acquisition system processes the reflected wave energy to determine at least one of a size, shape, and a material of the one or more wellbore hazards. Element 5: wherein the data acquisition system processes the reflected wave energy to determine a hardness of the material of the one or more wellbore hazards, and distinguishes two or more wellbore hazards from each other based on the hardness of the material of the two or more wellbore hazards. Element 6: wherein the wave energy includes at least one of acoustic waves, pressure pulses, electromagnetic waves, and radiant energy. Element 7: wherein the data acquisition system determines a distance of the one or more wellbore hazards from the downhole tool. Element 8: wherein the data acquisition system processes the reflected wave energy to display an image of the one or more wellbore hazards.

Element 9: wherein emitting the wave energy comprises generating a field of view having a pre-determined shape and extending a pre-determined distance from the downhole tool. Element 10: further comprising processing the reflected wave energy using the data acquisition system to determine at least one of a size, shape, and a material of the one or more wellbore hazards. Element 11: processing the reflected wave energy using the data acquisition system to determine a hardness of the material of the one or more wellbore hazards, and distinguishing two or more wellbore hazards from each other based on the hardness of the material of the two or more wellbore hazards. Element 12: wherein emitting the wave energy includes emitting at least one of acoustic waves, pressure pulses, electromagnetic waves, and radiant energy. Element 13: further comprising processing the reflected wave energy using the data acquisition system to determine a distance of the one or more wellbore hazards from the distal end of the downhole tool. Element 14: further comprising processing the reflected wave energy to display an image of the one or more wellbore hazards. Element 15: further comprising varying a frequency of the wave energy emitted by one or more sensing devices of the plurality of sensing devices to vary the image of the one or more wellbore hazards. Element 16: further comprising emitting the wave energy using the plurality of sensing devices located on a leading face of the downhole tool at a distal end thereof. Element 17: further comprising emitting the wave energy using the plurality of sensing devices located about the periphery of the downhole tool at a distal end thereof.

By way of non-limiting example, exemplary combinations applicable to A and B include: Element 4 with Element 5; Element 10 with Element 11; and Element 14 with Element 15.

Therefore, the disclosed systems and methods are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the teachings of the present disclosure may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present disclosure. The systems and methods illustratively disclosed herein may suitably be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series of items, with the terms “and” or “or” to separate any of the items, modifies the list as a whole, rather than each member of the list (i.e., each item). The phrase “at least one of” allows a meaning that includes at least one of any one of the items, and/or at least one of any combination of the items, and/or at least one of each of the items. By way of example, the phrases “at least one of A, B, and C” or “at least one of A, B, or C” each refer to only A, only B, or only C; any combination of A, B, and C; and/or at least one of each of A, B, and C.

The use of directional terms such as above, below, upper, lower, upward, downward, left, right, uphole, downhole and the like are used in relation to the illustrative embodiments as they are depicted in the figures, the upward direction being toward the top of the corresponding figure and the downward direction being toward the bottom of the corresponding figure, the uphole direction being toward the surface of the well and the downhole direction being toward the toe of the well. 

What is claimed is:
 1. A system, comprising: a downhole tool conveyable into a wellbore on a conveyance; a plurality of sensing devices positioned at a distal end of the downhole tool to emit wave energy in an axial direction within the wellbore, at least a portion of the wave energy being reflected by one or more wellbore hazards and received by the plurality of sensing devices; and a data acquisition system communicatively coupled to the downhole tool to receive and process reflected wave energy and thereby identify the one or more wellbore hazards.
 2. The system of claim 1, wherein the plurality of sensing devices are located on a leading face of the downhole tool.
 3. The system of claim 1, wherein the plurality of sensing devices are located about an outer periphery of the downhole tool at the distal end.
 4. The system of claim 1, wherein the wave energy emitted by the plurality of sensing devices exhibits a field of view having a pre-determined shape and extends a pre-determined distance from the distal end of the downhole tool.
 5. The system of claim 1, wherein the data acquisition system processes the reflected wave energy to determine at least one of a size, shape, and a material of the one or more wellbore hazards.
 6. The system of claim 5, wherein the data acquisition system processes the reflected wave energy to determine a hardness of the material of the one or more wellbore hazards, and distinguishes two or more wellbore hazards from each other based on the hardness of the material of the two or more wellbore hazards.
 7. The system of claim 1, wherein the wave energy includes at least one of acoustic waves, pressure pulses, electromagnetic waves, and radiant energy.
 8. The system of claim 1, wherein the data acquisition system determines a distance of the one or more wellbore hazards from the downhole tool.
 9. The system of claim 1, wherein the data acquisition system processes the reflected wave energy to display an image of the one or more wellbore hazards.
 10. A method, comprising: conveying a downhole tool into a wellbore on a conveyance; emitting wave energy in an axial direction within the wellbore using a plurality of sensing devices positioned at a distal end of the downhole tool, at least a portion of the wave energy being reflected by one or more wellbore hazards; receiving reflected wave energy using the plurality of sensing devices; receiving and processing the reflected wave energy with a data acquisition system communicatively coupled to the downhole tool; and identifying the one or more wellbore hazards with the data acquisition system based on the reflected wave energy.
 11. The method of claim 10, wherein emitting the wave energy comprises generating a field of view having a pre-determined shape and extending a pre-determined distance from the downhole tool.
 12. The method of claim 10, further comprising processing the reflected wave energy using the data acquisition system to determine at least one of a size, shape, and a material of the one or more wellbore hazards.
 13. The method of claim 12, further comprising: processing the reflected wave energy using the data acquisition system to determine a hardness of the material of the one or more wellbore hazards; and distinguishing two or more wellbore hazards from each other based on the hardness of the material of the two or more wellbore hazards.
 14. The method of claim 10, wherein emitting the wave energy includes emitting at least one of acoustic waves, pressure pulses, electromagnetic waves, and radiant energy.
 15. The method of claim 10, further comprising processing the reflected wave energy using the data acquisition system to determine a distance of the one or more wellbore hazards from the distal end of the downhole tool.
 16. The method of claim 10, further comprising processing the reflected wave energy to display an image of the one or more wellbore hazards.
 17. The method of claim 16, further comprising varying a frequency of the wave energy emitted by one or more sensing devices of the plurality of sensing devices to vary the image of the one or more wellbore hazards.
 18. The method of claim 10, further comprising emitting the wave energy using the plurality of sensing devices located on a leading face of the downhole tool at a distal end thereof.
 19. The method of claim 10, further comprising emitting the wave energy using the plurality of sensing devices located about the periphery of the downhole tool at a distal end thereof. 